Some subterranean deposits of viscous petroleum can be extracted in situ by lowering the viscosity of the petroleum to mobilize it so that it can be moved to, and recovered from, a production well. Reservoirs of such deposits may be referred to as reservoirs of heavy hydrocarbon, heavy oil, bitumen, tar sands, or oil sands. The in situ processes for recovering oil from oil sands typically involve the use of multiple wells drilled into the reservoir, and are assisted or aided by injecting a heated fluid such as steam into the reservoir formation from an injection well. In some in situ recovery processes, it is necessary or desirable to establish fluid communication between different wells. For example, in a steam-assisted gravity drainage (SAGD) process, fluid communication between an injection and production well pair is typically established as part of the start-up operation before a steam chamber is developed above the injection well.
A typical SAGD process is disclosed in U.S. Pat. No. 4,344,485 to Butler (“Butler”). In the process disclosed in Butler, two wells are drilled into the deposit, one for injection of steam and one for production of oil and water. Steam is injected via the injection well to heat the formation. As the steam condenses and gives up its heat to the formation, the viscous hydrocarbons are mobilized and drain by gravity toward the production well. Mobilized viscous hydrocarbons are recovered continuously through the production well. The conditions are chosen so that a very large steam saturated volume known as a steam chamber is formed in the formation adjacent to the injection well. The injection well is connected to this chamber and steam is injected continuously so as to maintain pressure in the steam chamber. At the boundary of the chamber, steam condenses and heat is transferred by conduction into the cooler surrounding regions. The temperature of the oil adjacent to the chamber is increased and it drains downwards continuously by gravity, along with the hot steam condensate, to the production well. In Butler, thermal communication between the injection and production wells is established before commencing production of oil. According to Butler, thermal communication is established when a relatively high permeability path from the injection well to the production well is established so that liquids heated by injected steam can drain continuously to the production well. Butler teaches that thermal communication between the wells can be established quickly by fracturing, i.e., forming a vertical fracture between the injection and production well pair by employing steam pressure above the fracture pressure, or by hydraulically fracturing the reservoir and propping it using appropriate proppants. For example, where the fracture pressure of the formation is 1200 psig (about 8.4 MPa), steam is introduced at 1300 psig (about 9.1 MPa). A vertical fracture is formed in the deposit extending above and below each well. After the drainage process has begun and a steam chamber has formed, the steam injection rate is reduced and the steam chamber pressure is allowed fall to the desired operating value, typically in the range of 100-500 psig.
Another SAGD process is described in CA 1,304,287 to Edmunds et al. (“Edmunds”). In this process, a pair of horizontal parallel co-extensive wells, one spaced closely above the other, are completed so that they extend through a heavy oil reservoir in close proximity to its base. The upper well is referred to as the injector and the lower as the producer. Each well has a screened liner and an inner tubing string extending the length of the well. Steam is circulated separately through each of the wells to heat by conduction the span of formation extending between the wells, to establish fluid communication between them. The circulation is conducted in through the tubing and out through the annulus at a pressure that is below the fracture pressure. The rate of production of effluent from each well is controlled to maintain its temperature at about 10-40° C. below the saturated steam temperature. Once communication is established, steam circulation in the producer is discontinued and the well is produced through the tubing. Steam is then injected through both the annulus and tubing of the injector. Steam condensate and oil are produced through the lower well. Steam-assisted gravity drainage is the mechanism thereafter used to heat the reservoir and produce oil.
A further SAGD process is described in U.S. Pat. No. 5,215,146 to Sanchez (“Sanchez”). Sanchez notes that steam breakthrough between the well pair in a SAGD process is more likely to occur at the point of closest spacing of the two wells. After the initial breakthrough, two very long horizontal wells (say 500 meters) could have a short section of only 1 or 2 meters having steam communication. As a result, the steam chamber can now grow only slowly along the length of the well. For long wells a complete formation of a steam chamber along the length of the wellbore may take several months, thereby reducing the effectiveness of the long wellbore. To solve this problem, Sanchez proposes adding foam while injecting steam into the injection well once steam breakthrough occurs in an inter-well region between the injection and production well pair. Foam enters the inter-well region thereby causing an increased pressure gradient. This increased pressure gradient adds to the gravity force thereby providing a greater interstitial oil velocity which increases oil drainage between wells during startup. According to Sanchez, adding form can reduce the time during which steam moves in a lateral direction between the well pair.
Jian-Yang Yuan and Richard McFarlane reviewed various techniques for start-up procedure in SAGD processes in a paper entitled “Evaluation of Steam Circulation Strategies for SAGD Start-Up,” Proceedings of the Canadian International Petroleum Conference (CIPC) 2009, Calgary, Alberta, Canada, 16-18 Jun., 2009, paper 2009-14 (“Yuan”). According to Yuan, the start-up procedure for SAGD requires the establishment of oil mobility between the well pair and requires that the intervening fluid between the well pair be heated to a temperature sufficiently high to cause the oil to flow from the injector to the producer. This is normally achieved by initially circulating steam in each well. The horizontal portion of each well can consist of tubing and liner, which provides two possible channels for fluid flow. In the simplest case, hot fluid can be injected into a steel tubing at the heel, flow from the heel to toe through the tubing, and then out through the annular space between tubing and liner from the toe towards the heel. The rate of heat transfer and fluid convection into the reservoir formation determine how communication is established along the length of the well pair. Once communication is established in a certain region along the well pair, drainage can be initiated in that region and subsequent steam injection will mainly be consumed by the steam chamber development around that region having the highest drainage rate. Ideally, it is desirable that this drainage region cover the entire length of the well pair. Depending on reservoir characteristics, this initial communication and drainage impact early production rate and even ultimate recovery. It is expected that steam injection rate, steam quality and the pressure drop between the two wells (ΔP) play critical roles. They also note that according to previous studies by others, no pressure differential between the well pair is required for start-up. When thermal conduction via steam circulation has heated the bitumen to between 50 and 100° C., the bitumen is sufficiently mobile so that it can be displaced by hot water and rapid convectional heating can occur. Under these conditions, and a small ΔP, steam breakthrough to the producer will take only a few days. Increasing the ΔP can increase fluid transport and convection; however this solution is not applicable once breakthrough has occurred anywhere along the well pair. Yuan notes that it is suggested by others that hot water injection could provide a better solution. The water will flow downwards, under gravity, from injector to producer more easily than water and bitumen resulting in a faster rate of heat transfer and communication. Yuan further notes that simulation analysis indicates that, for given tubing and liner sizes and reservoir properties, relatively lower circulation rates at high steam quality are more favorable for faster initialization and development of uniform temperature between the horizontal well pair; the use of high steam quality in combination with high circulation rates leads to slower rates of initialization, less uniform heating along the length of the wells, and possibility of premature steam breakthrough at the heel; and a small pressure difference (ΔP) between the well pair, offsetting the natural hydraulic pressure (50 kPa), appears to be more favorable for faster and more uniform initialization. They state that while a higher pressure difference can result in faster initialization, it can also result in less uniform heating and increasing the potential for premature steam breakthrough at the heel.
CA 2,240,786 to Lesage (“Lesage”) discloses heating an oil-sand formation by injecting steam into a horizontal section of a well and circulating it back to the surface. In the Lesage process, steam is initially continuously circulated in and out of the horizontal wellbore at a pressure below the formation's fracture pressure thereby heating the formation surrounding the horizontal wellbore by conduction to reduce the viscosity of the viscous oil. This step is continued until the temperature of the horizontal wellbore reaches the saturation temperature of steam at the horizontal wellbore pressure. Thereafter, the production is ceased and a slug of steam is injected and accumulated in and around the horizontal section, still at a pressure below the formation's fracture pressure. The well is then shut-in and is allowed to soak for a period of time, preferably from 1 to 7 days. After the soak period, the well is then opened for production and the continuous injection of steam is resumed soon after oil appears in the produced fluids. Lesage teaches that it is important not to fracture the formation because once fractured, most of the injected steam will flow into the fracture thereby making it very difficult to heat the formation along the length of the horizontal wellbore. While circulating steam, the steam injection pressure and the steam circulation rate can be controlled by adjusting chokes positioned in injection tubing at the surface. Conditioning of the formation is considered complete when the temperature within the horizontal wellbore reaches the saturation temperature of the steam at horizontal wellbore pressure as measured at the surface. Another indicator of completion is when the produced steam contains substantial amounts of produced oil. This step of heating the formation can typically take from about 20 to 100 days or longer, depending on well and/or formation parameters, injection and production pressures, steam quality, and circulation rates. Lesage further teaches that after the formation surrounding horizontal wellbore has been conditioned (i.e. heated) and some voidage has been created in the formation, the production tubing is closed and the injection of steam is continued through injection tubing. This injected steam now has no way to return to the surface, and accumulates as a “slug” within and around the horizontal wellbore. Injection of steam continues until the bottom-hole pressure in the wellbore approaches (i.e. nearly equals) the fracture pressure of the formation. At this time, the injection of steam is ceased, the well is shut-in, and the formation is allowed to “soak” for a period of time. Allowing the formation to soak results in heat being transferred from the steam by convective heating in addition to conductive heating. Although steam is injected below the fracture pressure of the formation, some degree of local failure of sand in shear (dilation) takes place and is advantageous to the process as it facilitates the entering of steam into the formation, thus resulting in convective heating.